CNL-24-077, Application for Subsequent Renewed Operating Licenses, Response to Request for Additional Information, Set 1

Application for Subsequent Renewed Operating Licenses, Response to Request for Additional Information, Set 1

ML24283A091
Person / Time
Site:	Browns Ferry
Issue date:	10/09/2024
From:	Edmondson C, Hulvey K Tennessee Valley Authority
To:	Office of Nuclear Reactor Regulation, Document Control Desk
References
CNL-24-077, EPID L-2024-SLE-0000
Download: ML24283A091 (1)

Text

1101 Market Street, Chattanooga, Tennessee 37402

CNL-24-077

October, 2024

10 CFR 54

ATTN: Document Control Desk U.S. Nuclear Regulatory Commission Washington, D.C. 20555-0001

Browns Ferry Nuclear Plant, Units 1, 2, and 3 Renewed Facility Operating License Nos. DPR-33, DPR-52, and DPR-68 NRC Docket Nos. 50-259, 50-260, and 50-296

Subject:

Browns Ferry Nuclear Plant, Units 1, 2, and 3 - Application for Subsequent Renewed Operating Licenses, Response to Request for Additional Information 6HW (EPID: L-2024-SLE-0000)

Reference:

1. Letter from TVA to NRC, CNL-24-001, "Browns Ferry Nuclear Plant, Units 1, 2, and 3 - Application for Subsequent Renewed Operating Licenses," dated January 19, 2024 (ML24019A010)

2. Letter from TVA to NRC, CNL-24-011, Browns Ferry Nuclear Plant, Units 1, 2, and 3 - Application for Subsequent Renewed Operating Licenses, Supplemental Information - Neutron Fluence Analyses Methodology, dated January 22, 2024 (ML24022A292)

3. NRC electronic mail to TVA, Browns Ferry SLRA - Request for Additional Information - Set #1, dated September 10, 2024 (ML24255A458)

By Reference 1, the Tennessee Valley Authority (TVA) submitted a subsequent license renewal application (SLRA) for the Browns Ferry Nuclear Plant (BFN), Units 1, 2, and 3, Renewed Facility Operating Licenses in accordance with Title 10 of the Code of Federal Regulations (10 CFR), Part 54, Requirements for Renewal of Operating Licenses for Nuclear Power Plants. By Reference 2, TVA provided the first supplement to the SLRA.

Since March 2024, TVA has been engaged with the Nuclear Regulatory Commission (NRC) staff in the safety audit of the SLRA. This audit has resulted in a request for additional information (RAI) (Reference 3). The TVA RAI response is provided in the enclosure to this letter.

U.S. Nuclear Regulatory Commission CNL-24-0 Page 2 October, 2024

There are no new regulatory commitments in this letter. Should you have any questions regarding this submittal, please contact Peter J. Donahue, Director, Subsequent License Renewal, at pjdonahue@tva.gov.

I declare under penalty of perjury that the foregoing is true and correct. Executed on this th day of October 2024.

Respectfully, Digitally signed by Edmondson, Carla Date: 2024.10.09 09:58:19 -04'00' Kimberly D. Hulvey General Manager, Nuclear Regulatory Affairs and Emergency Preparedness

Enclosure:

Response to Request For Additional Information by the Office Nuclear Reactor Regulation Browns Ferry Nuclear Plant, Units 1, 2, and 3 SLRA Docket Nos. 05000259, 05000260, 05000296 Issue Date: 09/10/2024

cc:

NRC Regional Administrator - Region II NRC Branch Chief - Region II NRC Senior Resident Inspector - Browns Ferry Nuclear Plant NRC Project Manager, License Renewal Projects Branch (Safety)

State Health Officer, Alabama Department of Public Health (w/o Enclosure)

Enclosure

Response to Request For Additional Information by the Office Nuclear Reactor Regulation Browns Ferry Nuclear Plant, Units 1, 2, and 3 SLRA Docket Nos. 05000259, 05000260, 05000296 Issue Date: 09/10/2024 Enclosure

The Nuclear Regulatory Commission (NRC) Request for Additional Information provided the following background discussion.

Regulatory Basis

10 CFR 54.21(a)(3) requires an applicant to demonstrate that the effects of aging for structures and components will be adequately managed so that the intended function(s) will be maintained consistent with the current licensing basis for the period of extended operation. One of the findings that the staff must make to issue a renewed license (10 CFR 54.29(a)) is that actions have been identified and have been or will be taken with respect to managing the effects of aging during the period of extended operation on the functionality of structures and components that have been identified to require review under 10 CFR 54.21, such that there is reasonable assurance that the activities authorized by the renewed license will continue to be conducted in accordance with the current licensing basis. In order to complete its review and enable making a finding under 10 CFR 54.29(a), the staff requires additional information in regard to the matters described below.

RAI B.2.1.27-1

Background:

GALL-SLR Report AMP XI.M41, Buried and Underground Piping and Tanks, Table XI.M41 -1, Preventive Actions for Buried and Underground Piping and Tanks, recommends that cathodic protection is provided for buried steel piping. In addition, GALL-SLR Report AMP XI.M41 states the following:

x [f]ailure to provide cathodic protection in accordance with Table XI.M41-1 may be acceptable if justified in the SLRA. The justification addresses soil sample locations, soil sample results, the methodology and results of how the overall soil corrosivity was determined, pipe to soil potential measurements and other relevant parameters. If cathodic protection is not provided for any reason, the applicant reviews the most recent 10 years of plant-specific operating experience (OE) to determine if degraded conditions that would not have met the acceptance criteria of this AMP have occurred. This search includes components that are not in -scope for license renewal if, when compared to in -scope piping, they are [of] similar materials and coating systems and are buried in a similar soil environment. The results of this expanded plant -specific OE search are included in the SLRA.

x [a]dditional inspections, beyond those in Table XI.M41-2 [Inspection of Buried and Underground Piping and Tanks] may be appropriate if exceptions are taken to program element 2, preventive actions, or in response to plant-specific OE.

Exception No. 1 to SLRA Section B.2.1.27, Buried and Underground Piping and Tanks, documents the basis for why the installation of a cathodic protection system to protect buried steel piping is impractical at Browns Ferry Nuclear Plant (BFN). In addition, based on its review of SLRA Section B.2.1.27, the staff noted six inspections of buried steel piping will be conducted in each 10-year interval, consistent with Preventive Action Category E defined in GALL -SLR Report Table XI.M41-2 (adjusted for a three -unit site). Furthermore, SLRA Section B.2.1.27 states the following:

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x based on review of BFN-specific operating experience, no leaks in the subject buried piping due to external corrosion have been observed and no significant buried piping coating degradation has been observed.

x [f]rom the 2009 soil sample APEC [Area Potential Earth Current] survey there were 6 recommended inspection locations that could possibly reflect localized areas of potential coating damage and active corrosion. It was recommended that these locations be excavated and directly inspected. There were also 6 locations recommended for excavation and direct examination based on the 8 soil samples from 2023 combined with the 48 total native potential measurements recorded as CIS [Close Interval Survey].

During its audit, the staff noted several instances of buried piping leaks and an instance of buried piping not being coated in accordance with design specifications. The first three examples below are related to buried service air piping (not in -scope based on the systems listed in SLRA Section B.2.1.27 (page B -119)) and the 4th and 5th examples are related to buried fire protection piping (in -scope based on the systems listed in SLRA Section B.2.1.27 (page B-119)).

1. The staff reviewed CR 793555 and noted the suspected cause of the leak was corrosion similar to that seen in two service air piping leaks earlier in 2013.

2. The staff reviewed CR 1120048 and noted the source of the leak was determined to be service air and not fire protection.

3. The staff reviewed CR 898407 and noted (a) a section of service air piping had no visible exterior tape coating or polyethylene coating as required by design drawings; and (b) the uncoated section of piping had multiple thru wall holes.

4. The staff reviewed CR 828934 and noted it was indeterminate whether the leak was coming from a slipjoint between sections of pipe or a hole in the pipe wall.

5. The staff reviewed CR 1102016 and noted that a contributing cause of a break in buried fire protection piping was outer diameter graphitic corrosion. The staff noted that although managing loss of material due to graphitic corrosion is not within the scope of the Buried and Underground Piping and Tanks program, it does provide evidence that in -scope buried steel piping is potentially exposed to an aggressive environment.

During its audit, the staff reviewed SL -016653, Evaluation of Cathodic Protection for Buried Piping, which noted that a site -wide impressed current cathodic protection (ICCP) system is not likely to be successful; however, it also notes that protecting a small scope of buried piping that is high-risk due to the pipe construction, process fluid, or the soil conditions in the area is likely achievable. The staff also reviewed BP -2023-0027-03-TR, Browns Ferry License Renewal Buried Piping Cathodic Protection Review, which provides a similar discussion.

Issue:

During its audit, the staff noted several instances of leaks and an instance of buried piping not being coated in accordance with design specifications. It is the staffs understanding that the OE described in the CRs above did not involve in -scope buried steel piping; however, the staff seeks additional information with respect to why the condition of piping documented in theses CRs is not representative of the condition of in -scope buried steel piping.

The staff recognizes that installation of a site -wide ICCP system is likely impractical at BFN.

However, based on its review of SL -016653 and BP-2023-0027-03-TR, it appears that protecting a limited scope of high -risk in-scope buried steel piping may be practical. The staff

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seeks additional information with respect to why providing cathodic protection for a limited scope of high -risk in-scope buried steel piping is considered impractical.

The 2009 and 2023 soil surveys referenced above recommended six inspection locations that could possibly reflect localized areas of potential coating damage and active corrosion. The staff noted that this also corresponds to the recommended number of inspections for Preventive Action Category E in GALL -SLR Report Table XI.M41 -2 (adjusted for a three -unit site). Since coatings are the only barriers to aging at BFN, and coatings will continue to degrade over time, the staff seeks additional information with respect to why increased inspection quantities (beyond those prescribed in GALL -SLR Report Table XI.M41-2) are not necessary to provide reasonable assurance that loss of material on the external surfaces of in -scope buried steel piping will be adequately managed during the subsequent period of extended operation.

Request:

Provide additional information documenting the basis for why the condition of piping documented in the CRs above is not representative of the condition of in -scope buried steel piping. Include a discussion of the following as a minimum:

1. Similarities or differences in materials of construction for (a) in -scope buried steel piping; (b) buried service air piping referenced in the CRs above; and (c) buried fire protection piping referenced in the CRs above.

2. Similarities or differences in external coating types used for (a) in -scope buried steel piping; (b) buried service air piping referenced in the CRs above; and (c) buried fire protection piping referenced in the CRs above.

3. Similarities or differences in soil corrosivity in the vicinity of (a) in -scope buried steel piping; (b) buried service air piping referenced in the CRs above; and (c) buried fire protection piping referenced in the CRs above.

4. Detailed results of inspections of in -scope buried steel piping, including whether the piping was externally coated in accordance with design specifications.

Provide additional information documenting the basis for why providing cathodic protection for a limited scope of high -risk in-scope buried steel piping is considered impractical.

Based on plant-specific OE and the absence of cathodic protection, state the basis for why increased inspection quantities (beyond those prescribed in GALL -SLR Report Table XI.M41-2) are not necessary to provide reasonable assurance that loss of material on the external surfaces of in-scope buried steel piping will be adequately managed during the subsequent period of extended operation.

TVA Response

Additional information on the referenced condition reports (CR).

CR 793554 - Initiated 10/15/2013 and CR 1120048 - Date Reported: 12/30/2015

Note: CR 793555 was referenced above. We believe this to be a typo. CR 793554 refers to a piping failure.

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These CRs discuss the same break in service air pipe. Work order (WO) 117468008 was generated to fix the leak, which was cancelled to WO 115193847. WO 115193847 was to install temporary repairs and be worked concurrent with WO 118320795 for permanent repairs and WO 114394625 to inspect the pipe. According to the work performed in WO 118320795, once the crew excavated the pipe, they found a through-wall leak in the piping and the piping was also broken at the penetration to the intake building. Repairs could not be completed due to many obstructions (other piping, bus ducts, etc.). Temporary repairs were completed and permanent repairs are pending an engineering change. CRs 1860563 and 1854648 were generated. The pipe material was carbon steel and the coating was polyethylene. The buried piping engineer was present and performed an inspection and determined the cause of the through-wall leak was internal corrosion.

CR 898407 - Date Reported: 06/13/2014

Service air leak located on a berm on the south side of the reactor building. This piping had multiple through-wall leaks and was uncoated. The suspected cause for the leak is corrosion where a small portion of the pipe was not coated. The uncoated piping was all excavated back to coated piping and replaced. The replacement piping was factory coated with polyethylene and the fittings were field coated with Tapecoat.

CR 828934

On January 6, 2014, Fire Operations identified a greater than 100 gallons per minute leak in fire protection (FP) system at the west end of cooling tower #2. Valve 0-26-1019-2 was isolated which stopped the leak. The pipe was replaced under WO 115412546. The pipe was circumferentially cracked. A heavy load above ground caused this pipe failure, likely due to unintended vehicle traffic.

CR 1102016

On November 7, 2015, a leak was discovered on a 14 high pressure fire protection pipe. The CR states that the direct cause of this failure was due to heavy external loading due to vehicular (crane) traffic. Minimum wall analysis was performed on this pipe as part of the failure mechanism analysis, and it determined that even in the areas of greatest selective leaching, there were 292 mils of wall remaining, which is above the minimum wall required thickness of 65 mils. Assuming a linear wear rate based on the age of the component, this pipe would have a remaining service life of an additional 42 years with selective leaching. It is critical to note that the minimum wall thickness is based on the piping design. Because the component had sufficient minimum wall with selective leaching, it would have been able to meet its intended function. However, by design, the component was not intended to be exposed to external forces due to heavy vehicular traffic. Therefore, the applicable minimum wall design criteria was not sufficient for this unforeseen external loading. The selective leaching present on this component was still within design margin and within allowable corrosion.

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Request 1

Similarities and Differences in Piping Material

Table 1 - Similarities and Differences in Piping Material

CR# System Piping Type Similarities to In-Scope Material Differences from In-Scope Piping Piping 793554 / Service Air Carbon SA piping is small bore CS; The difference between the buried 1120048 (SA) Steel in-scope piping contains SA piping and buried in-scope CS (CS) carbon steel. piping is the quality control. In-scope CS piping is mostly designed to B31.1.0, Section 1, 1967. SA piping is considered run-to-failure and is not code regulated.

898407 Service Air Carbon SA piping is small bore CS; The difference between the buried Steel in-scope piping contains SA piping and buried in-scope CS carbon steel. piping is the quality control. In-scope CS piping is mostly designed to B31.1.0, Section 1, 1967. SA piping is considered run-to-failure and is not code regulated.

828934 Fire Grey This piping is in-scope; The FP segments covered in Protection Cast however, it is managed with CR 828934 are constructed of Iron NFPA 25 in accordance with cement lined grey cast iron. Non-FP Generic Aging Lessons in-scope piping is CS piping Learned for Subsequent designed to B31.1.0.

License Renewal (GALL-SLR) XI.M41.

1102016 Fire Grey This piping is in-scope; The FP segments covered in CR Protection Cast however, it is managed with 1102016 are constructed of cement Iron NFPA 25 in accordance with lined grey cast iron. Non-FP in-scope GALL-SLR XI.M41. piping is CS piping designed to B31.1.0.

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Request 2:

Similarities and Differences in Coating Type

Table 2 - Similarities and Differences in Coating Type

CR# System Coating Type Similarities to In-Scope Differences from In-Scope Piping Piping 793554 / Service Air Some are None, SA pipe is generally 1. SA has polyethylene 1120048 coated with coated with polyethylene, and coating while in-scope Tapecoat and tape coated at the fittings and carbon steel piping has Polyethylene welds. The leak locations multi-layer coating system coatings; based were not coated. as specified by AWWA on descriptions, C203-66 A1.5.

the piping was 2. The major difference is uncoated in that the SA piping was not failure locations. coated at the leak locations.

3. In-scope piping was holiday tested per above coating specification. The SA piping, with sections uncoated, had not been holiday tested; otherwise, uncoated sections would have been discovered.

4. The SA piping is run-to-failure.

898407 Service Air Section of pipe None, SA pipe is generally 1. SA has polyethylene was not coated coated with polyethylene, and coating while in-scope per G-55 tape coated at the fittings and carbon steel piping has specification. welds. The leak locations were multi-layer coating system not coated. as specified by AWWA C203-66 A1.5.

2. The major difference is that the SA piping was not coated at the leak locations.

3. In-scope piping was holiday tested per above coating specification. The SA piping, with sections uncoated, had not been holiday tested; otherwise, uncoated sections would have been discovered.

4. The SA piping is run-to-failure.

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CR# System Coating Type Similarities to In-Scope Differences from In-Scope Piping Piping 828934 Fire Coal-tar Varnish FP piping is considered FP piping, built in Protection in-scope; however, it is accordance with NFPA 24, managed with NFPA 25 in has coal tar varnish coating.

accordance with GALL-SLR Carbon steel in-scope piping XI.M41. It is coated with coal has a multi-layer coating tar varnish. There are no system as specified by similarities between FP AWWA C203-66 A1.5.

coatings and the other in-scope piping.

1102016 Fire Coal-tar Varnish FP piping is considered FP piping, built in Protection in-scope; however, it is accordance with NFPA 24, managed with NFPA 25 in has coal tar varnish coating.

accordance with GALL-SLR Carbon steel in-scope piping XI.M41. It is coated with coal has a multi-layer coating tar varnish. There are no system as specified by similarities between FP AWWA C203-66 A1.5.

coatings and the other in-scope piping.

In-scope carbon steel piping externa l coatings are the AWWA C203-66 A1.5 multi-layer coal tar with asbestos wrap coating that have seen very little degradation in buried environments. It is important to note that the service air piping referenced in the CRs is not in-scope of license renewal and is commercial, so it did not have the same rigor of configuration controls during construction. In-scope piping was tested for holidays at the time of installation.

Fire protection piping is a coal tar varnish, which is widely used in the US nuclear fleet. While fire protection piping is coated in accordance with a different standard than the coating used for in-scope carbon steel piping, the two fire protection piping failures noted were primarily caused by above ground traffic, rather than corrosion.

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Request 3

Similarities and Differences in Soil Environment

Table 3 - Similarities and Differences in Soil Environment

CR# System Soil Environment Characterization Similarities to In-Scope Differences from In-Scope Piping Piping 793554 / Service Air Native Soil. Similarities are based on 1. Soil analysis performed for 1120048 No characterization a visual observation of in-scope piping shows available. No the soil during the moderate corrosivity according previous soil sample excavation of SA piping to criteria provided in Electric was taken from this and described as native Power Research Institute location. clay with sand mix (EPRI) Report 3002005294.

Characterization was backfill for both in-scope No soil data obtained not determined to be and SA piping. specifically for SA/FP piping.

necessary at the 2. TVA General Engineering time of inspection Specification G-9 applies to due to run-to-failure in-scope piping and specifies status. No in-scope bedding, compaction, piping is in this allowable granular material location, so no soil size, and testing. Controls on sampling was backfill for run-to-failure SA performed in piping are not documented.

preparation for SLR As stated above, varying one in this area. Higher or more soil parameters can scrutiny of backfill affect corrosivity. A visual was used for observation of the soil / backfill in-scope piping is likely not capable of system install. determining the corrosivity in the vicinity of the SA piping leaks. A visual description of the soil cannot be directly equated to soil corrosivity since the source of the native clay and sand likely does not have the same quality controls.

More importantly, the remaining soil factors related to corrosivity are unknown for SA piping. Sample ID #2 from the 2009 soil survey, Table 1 GSE report BP-2023-0027 TR, is an example of the effect one soil characteristic

(% gravel) can have on corrosivity.

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CR# System Soil Environment Characterization Similarities to In-Scope Differences from In-Scope Piping Piping 898407 Service Air Native Soil. Similarities are based on 1. Soil analysis performed for No characterization a visual observation of in-scope piping shows available. No the soil during the moderate corrosivity according previous soil sample excavation of SA piping to criteria provided in EPRI was taken from this and described as native Report 3002005294. No soil location. clay with sand mix data obtained specifically for Characterization was backfill for both in-scope SA/FP piping.

not determined to be and SA piping. 2. TVA General Engineering necessary at the Specification G-9 applies to in-time of inspection scope piping and specifies due to run-to-failure bedding, compaction, status. No in-scope allowable granular material piping is in this size, and testing. Controls on location, so no soil backfill for run-to-failure SA sampling was piping are not documented.

performed in As stated above, varying one preparation for SLR or more soil parameters can in this area. Higher affect corrosivity. A visual scrutiny of backfill observation of the soil / backfill was used for is likely not capable of in-scope piping determining the corrosivity in system install. the vicinity of the SA piping leaks. A visual description of the soil cannot be directly equated to soil corrosivity since the source of the native clay and sand likely does not have the same quality controls.

More importantly, the remaining soil factors related to corrosivity are unknown for SA piping. Sample ID #2 from the 2009 soil survey, Table 1 GSE report BP-2023-0027 TR, is an example of the effect one soil characteristic

(% gravel) can have on corrosivity.

828934 Fire Native Soil. FP piping is considered Soil analysis performed for Protection No characterization in-scope; however, it is in-scope piping shows available. No managed with NFPA 25 moderate corrosivity according previous soil sample in accordance with to criteria provided in EPRI was taken from this GALL-SLR XI.M41. Report 3002005294. No soil environment. Backfill has been data obtained specifically for Characterization was described as native clay. SA/FP piping.

not determined to be necessary at the time of inspection.

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CR# System Soil Environment Characterization Similarities to In-Scope Differences from In-Scope Piping Piping 1102016 Fire No characterization FP piping is considered Soil analysis performed for Protection available. in-scope; however, it is in-scope piping shows managed with NFPA 25 moderate corrosivity according in accordance with to criteria provided in EPRI GALL-SLR XI.M41. Report 3002005294. No soil Backfill has been data obtained specifically for described as native clay. SA/FP piping.

The safety related in-scope piping was surrounded with sand before the native fill was added in accordance with TVA General Engineering Specification G-9, Earth and Rock Foundation and Fills During Construction, Modification, and Maintenance for Nuclear Plants (Quality-Reviewed Document). In the pictures of the service air piping and high-pressure fire protection piping, it appears that very little sand was added, if any. All soil sampling was performed in accordance with the criteria provided in EPRI Report 3002005294.

Request 4

Detailed Inspection Results of In-Scope Buried Steel Piping

Coatings have been effective in protecting in-scope buried piping from degradation. The few instances of piping degradation that have occurred were caused by internal corrosion or mechanical damage. Site-specific operating experience (OE) shows that the coatings are effective, including internal and external piping inspections, representative soil samples taken for SLR efforts showing non-aggressive soil at piping depth, and the Area Potential Earth Current (APEC) survey. To date, no coating degradation has been found on in-scope steel buried pipe which would require an extent of condition evaluation. No external corrosion has been observed on in-scope steel buried pipe.

1. 24 residual heat removal service water (RHRSW) WO 10-710139-000/ BFN-1-PIPE-023/0-23003-24-01-BA and 18 emergency equipment cooling water (EECW) WO 10-710139-000/

BFN-1-PIPE-077/0-77004-14-02-AC piping was inspected and showed coating coal ta r with asbestos wrap in accordance with AWWA C203-66 A1.5. This inspection was completed in 2010. The coating was in excellent condition with minor damage attributed to excavati on activity. This location corresponds to Structural In tegrity Associates APEC survey location 6, which is between recommended locations 9 and 12. This excavation was performed as proof that the coatings systems are robust and in tact.

2. Standby Gas Treatment (SBGT) WO 112417467 and 115363058 follow-up inspectio n/repair for leak in 2015. The process fluid for this line is gaseous. Gravel was found in the SBGT equipment/piping, indicating the issue. The pipe was found to be separat ed at a mechanical joint where the pipe penetrates the reactor building. The cause of the separation app eared to be 7 inches of pipe settlement due to ground movement. When the penetration issue was identified, ultrasonic testing (UT) was performed, and no minimum wall issues were f ound.

Coating was well adhered to the gen eral piping, but at the location where the pipe jo int was separated by settling, the outer layer of tape was noted as found partially disbonded. The coal tar was well-adhered and no bare metal was exposed. The coating was found in accordance with AWWA C203-66 A1.5. Leakage appears to be at a partially separated joint caused by extensive settling. Numerous photos were taken of the completely intact and seemingly unchanged coating. It is important to note that the excavation area was open for

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at least four months prior to the coating inspection being performed, and the as-found condition was not documented. The inspected area showed no evidence of pipe depressions (dimples) and welds did not show signs of degradation.

Why providing cathodic protection for a limited scope of high-risk in-scope buried steel piping is considered impractical:

As described in SL-016653, a distributed anode bed system requires up to 20 anode beds at 20 foot depth, with each anode bed comprised of ten 18-inch anode columns, spaced 20 feet apart.

This requires long lengths of cable trenching to connect the system together.

The specific issue with BFN implementing this design is the arrangement of the plant piping.

The site is located between the plant and the river/canal; the congested piping in this area includes RHRSW, EECW, fire protection, raw water, and other buried commodities. These lines are nested in some locations, with many lines in close proximity and some routed perpendicular to each other. There are other barriers such as buildings, duct banks, and paved areas making it very difficult to locate the distributed anode. Given the shielding effect of these structures and configured piping, cathodic currents would be prevented from reaching sections of targeted piping.

Protecting the entire site with this system would be impractical due to the large number of anodes and related trenching and excavations. Stray current would need to be evaluated for its effect on existing plant structures. As noted above, piping systems at BFN are in very close proximity to each other, which would make separating out a small scope of targeted piping problematic and impractical. The challenges with this design at BFN include properly locating anodes, shielding, and stray current corrosion. Stray current corrosion would adversely affect metals in the ground which are not bonded to the proposed cathodic protection (CP) system, including piping, structures, etc. Stray current corrosion is a phenomenon in which non-bonded metal within the influence of the anodes becomes anodic itself and corrodes at a faster rate than it would otherwise. Fire protection piping, as well as any piping or metallic structures not bonded to the proposed CP system, would be negatively affected by stray current corrosion. As previously discussed in the application, the fire protection piping cannot be bonded to the CP system because it is not electrically continuous.

The decision to design BFN without cathodic protection was the recommendation of TVAs Cathodic Protection Task Force, instead relying on robust coatings, painting, and proper selection of material for corrosion protection. To date, BFN Nuclear Energy Institute 09-14 Buried Pipe Program has not identified a limited scope of high-risk (i.e., susceptibility to degradation and consequences of failure), in-scope, buried steel piping. Impracticalities include shielding, nested piping, stray current corrosion, and anode bed placement.

The installation of a CP system is still impractical, and though it may be possible for a hypothetical small scope of targeted piping, any potential benefit would be far outweighed by the challenges (shielding, nested piping, and anode placement) and would cause adverse effects (stray current corrosion).

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Describe why increased inspection quantities (beyond those prescribed in GALL-SLR Report Table XI.M41-2) are not necessary to provide reasonable assurance that loss of material on the external surfaces of in-scope buried steel piping will be adequately managed during the subsequent period of extended operation:

BFN will be using the corrective action program in accordance with Element 7 of the Buried Pipe Aging Management Program (AMP) and Operating Experience in accordance with Element 10 of the Buried Pipe AMP to inform inspections, in addition to AMP guidance. If, when initial inspections are performed, age-related degradation is found, the location will be repaired or replaced, and the number of inspections will be increased in accordance with guidance in the AMP, which is consistent with GALL-SLR.

In GALL-SLR XI.M41 Element 7, Corrective Actions, coating degradation alone does not necessitate additional inspections. BFN has not observed any coating degradation that was not excavation-induced with in-scope piping. If coating degradation is caused by the backfill, an extent of condition evaluation is performed to determine the extent of degraded backfill. All of the in-scope piping backfill has been satisfactory. Soil surveys show moderate corrosivity by EPRI standards noted in report #3002005294, with more threatening reagents such as chlorides below the low level recording limits.

The APEC survey indicates a current draw, which could be indicative of many things, including (but not limited to) coating transitions, coating flaws, or external corrosion. Several of the locations in the APEC survey were followed up on with visual inspection, UT, and guided wave UT, and no coating degradation or external corrosion was found. In-scope piping and out-of-scope piping was inspected based on APEC results. One location was excavated based on APEC results. No issue was found at the indicated location; however, guided wave UT indicated a feature outside of the excavation requiring disposition. The excavation was expanded and a failed weld, which had initiated from the inside diameter of the pipe, was discovered when the pristine coating was removed. The coating was still very much intact. This occurred on out-of-scope piping in the vicinity of APEC inspection location 1, which corresponds to recommendation location 7 from Table B.2.1.27-1. The other instances found coating transitions from factory-applied coating to field-applied coating. For these inspections, coating was removed at the transitions to ensure the substrate was not corroded, and the rest of the coating was inspected. No issues were found.

In addition to site-specific OE, industry experience is also monitored. Other sites have the same type of AWWA C203-66 A1.5 coating on their in-scope buried piping. If age-related degradation is reported, BFN will evaluate the OE in the corrective action program and modify the AMP accordingly.

BFNs OE with in-scope buried piping and the compact nature of the three-unit site does not indicate that increased inspections beyond those prescribed in Table XI.M41-2 are necessary.

The GALL-SLR program is generic to be applicable to the entire US industry. BFN has more common building usage and a more congested piping layout when compared with other, more geographically-independent, multi-unit sites, which leads to the inspections being more representative of the site (i.e., more piping in the direct vicinity of soil sample locations, etc.).

Results of the direct inspection, as evaluated in the corrective action program, will dictate future actions. If aging degradation is found, the corrective action process will determine if additional inspections are necessary for bounding an extent of condition. Inspections will be performed by a qualified coatings inspector and will be performed in accordance with the requirements described in SLRA Section B.2.1.27. The positive plant OE, current direct inspection plans, soil

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sampling, and robust coatings provide adequate aging management and reasonable assurance that in-scope buried piping and components will perform their intended function during the subsequent period of extended operation. BFN will follow GALL-SLR XI.M41 Element 7 and Element 10 to determine if additional inspections are necessary as information is available.

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